Method and system for evaluating task completion times to data

ABSTRACT

The present invention is directed to methods of evaluating the operations of a well service rig at a well site by evaluating charts of sensor data obtained from sensors on or associated with the well service rig. An activity listing or Gantt chart can be reviewed and each activity verified by viewing charts of sensor data obtained during that purported activity. In addition service rig downtimes can be determined and evaluated through the evaluation of charts of sensor data. Furthermore, activities and completion times for each activity can be determined by evaluating charts of sensor data obtained from sensors on the service rig or at the well site to verify the operations of the service rig, to improve the efficiency of the operators by identifying long activities and providing additional instruction, and provide improved billing to customers by correcting activities and the time associated therewith.

STATEMENT OF RELATED PATENT APPLICATION

This non-provisional patent application claims priority under 35 U.S.C. § 119 to U.S. Provisional Patent Application No. 60/716,612, titled Interpretive Techniques Using Sensor Data, filed Sep. 13, 2005. This provisional application is hereby fully incorporated herein by reference.

FIELD OF THE INVENTION

The technical field of the present invention relates generally to evaluation of data concerning servicing hydrocarbon wells and more specifically to an evaluation of data obtained from a computerized work over rig adapted to record and transmit data concerning well servicing activities and conditions at a well site.

BACKGROUND OF THE INVENTION

After a well has been drilled, it must be completed before it can produce gas or oil. Once completed, a variety of events may occur to the formation, the well and its equipment that requires a “work-over.” For purposes of this application, “work-over” and “service” operations are used in their very broadest sense to refer to any and all activities performed on or for a well to repair or rehabilitate the well, and also includes activities to shut in or cap the well. Generally, work over operations include such things as replacing worn or damaged parts (e.g., a pump, sucker rods, tubing, and packer glands), applying secondary or tertiary recovery techniques, such as chemical or hot oil treatments, cementing the well bore, and logging the well bore to name just a few. Service operations are usually performed by or involve a mobile work-over or well service rig that is adapted to, among other things, pull the well tubing or rods and also to run the tubing or rods back in. Typically, these mobile service rigs are motor vehicle-based and have an extendible, jack-up derrick complete with draw works and block. In addition to the service or service rig, additional service companies and equipment may be involved to provide specialize operations. Examples of such specialized services includes: a chemical tanker, a cementing truck or trailer, a well logging truck, perforating truck, and a hot-oiler truck or trailer.

It is conventional for a well owner to contract with a service company to provide all or a portion of the necessary work-over operations. For example, a well owner, or customer, may contract with a service rig provider to pull the tubing from a specific well, contract with one or more service providers to provide other specific services in conjunction with the service rig company so that the well can be rehabilitated according to the owner's direction.

It is typical for the well owner to receive individual invoices for services rendered from each company that was involved in the work over. For example, if the portable service rig spent thirty hours at the well site, the customer well owner will be billed for thirty rig hours at the prevailing hourly rate. The customer is rarely provided any detail on this bill as to when the various other individual operations were started or completed, or how much material was used. Occasionally, the customer might be supplied with handwritten notes from the rig operator, but such is the exception, not the rule. Similarly, the customer will receive invoices from the other service companies that were involved with working over the well. The customer is often left with little to no indication of whether the service operation for which it is billed were done properly, and in some cases, even done at all. Further, most well owners own more than one well in a given field and the invoices from the various companies may confuse the well name with the services rendered. Also, if an accident or some other notable incident occurs at the well site during a service operation, it may be difficult to determine the root cause or who was involved because there is rarely any documentation of what actually went on at the well site. Of course, a well owner can have one of his agents at the well site to monitor the work-over operations and report back to the owner, but such “hands-on” reporting is often times prohibitively expensive.

The present invention is directed to ameliorating these and other problems associated with oil well work-over operations.

SUMMARY OF THE INVENTION

The present invention is directed to incrementing a well service rig in such a manner that activity-based and/or time-based data for the well site is recorded and evaluated. The invention contemplates that the acquired data can be transmitted in near real-time or periodically via wired, wireless, satellite or physical transfer such as by memory module to a data center preferably controlled by the service rig owner, but alternately controlled by the well owner or another.

For one aspect of the present invention, a method of determining the accuracy of an activity listing for activities completed by a well service rig at a well site can include determining a first activity from an activity listing, such as a Gantt chart. Charts of sensor data can be evaluated. The charts can be of sensor data obtained from sensors on the well service rig and the data can be associated with work completed at the well site by the service rig, other service vehicles or by third party operators. An evaluation of the charts of sensor data can be conducted to determine if the activity listed in the Gantt chart corresponds with the data that is being received from the sensors and displayed on the data charts.

For another aspect of the present invention, a method of determining the completion times for an activity completed by a well service rig at a well site can be determined by evaluating one or more charts of sensor data associated with work completed at the well site. An activity can be determined through the evaluation of the charts of sensor data and the time to complete that activity can be determined. Once determined, the completion time can be recorded in a computer program.

For yet another aspect of the present invention, method of determining service rig downtime can be achieved by evaluating one or more charts of sensor data associated with work completed at the well site. Each chart of sensor data can be evaluated to determine if a portion of the data on that particular chart includes a substantially flat or missing string of data for a predetermined length of time, for example, fifteen minutes. The time period of the substantially flat or missing data can be determined and other charts of sensor data can be evaluated to determined if they have substantially flat or missing data for the same time period.

BRIEF DESCRIPTION OF DRAWINGS

For a more complete understanding of the exemplary embodiments of the present invention and the advantages thereof, reference is now made to the following description in conjunction with the accompanying drawings in which:

FIGS. 1A and 1B are flowcharts of an exemplary process for of a well servicing activity cycle according to one exemplary embodiment of the present invention;

FIG. 2 illustrates one embodiment an activity capture methodology outlined in tabular form according to one exemplary embodiment of the present invention;

FIG. 3 provides a frontal view of an exemplary operator interface according to one exemplary embodiment of the present invention;

FIG. 4 provides an illustration of an exemplary activity capture map according to one exemplary embodiment of the present invention;

FIG. 5 is a side view of a mobile service rig with its derrick extended according to one exemplary embodiment of the present invention;

FIG. 6 is a side view of the mobile service rig illustrating the raising and lowering of an inner tubing string according to one exemplary embodiment of the present invention;

FIGS. 7, 7A, and 8 are exemplary displays that include activity Gantt charts according to one exemplary embodiment of the present invention;

FIG. 9 is a flowchart of an exemplary process for evaluating and determining the accuracy of an activity Gantt chart according to one exemplary embodiment of the present invention;

FIG. 10 is an exemplary electronic display of readings from sensors on a mobile service rig according to one exemplary embodiment of the present invention;

FIG. 11 is a flowchart of an exemplary process for measuring completion times for jobs completed by evaluating the exemplary electronic display of readings from sensors on the mobile service rig according to one exemplary embodiment of the present invention;

FIG. 12 is an exemplary electronic display of readings from sensors on a mobile service rig according to one exemplary embodiment of the present invention; and

FIG. 13 is a flowchart of an exemplary process for determining downtime by evaluating the exemplary electronic display of readings from sensors on the mobile service rig according to one exemplary embodiment of the present invention.

DETAILED DESCRIPTION OF THE EXEMPLARY EMBODIMENTS

Because the mobile service rig is typically the center of work-over or service operations at the well site, the present invention is directed to incrementing the service rig in such a manner that activity-based and/or time-based data for the well site is recorded. The invention contemplates that the acquired data can be transmitted in near real-time or periodically via wired, wireless, satellite or physical transfer such as by memory module to a data center preferably controlled by the service rig owner, but alternately controlled by the well owner or another. The data can thereafter be used to evaluate the data and supervise from off-site the activities of the well service rig. This latter implementation of the invention permits a service rig owner, supervisor, or well-owner customer to monitor the work being completed by the well service rig and other third parties based on data that is provided and can be reviewed after the fact or substantially in real-time. As described below in more detail, by accessing the data through a regularly updated web portal, the customer may be able to determine in near real time that, for example, the tubing pull will be completed in approximately two hours, how long the pull took, and whether to time to complete was excessive due to other operations or unexpected or wasted downtime. With such information, the owner or supervisor can provide customers with more accurate billing and train or discipline service rig crews based on their activities and their completion times. Further, the customer will have access to detailed data on the actual service performed and can then verify its invoices. In addition, the owner or supervisor can evaluate the data to determine the efficiency and correctness of the reports generated by the service rig operator.

The present invention fosters a synergistic relationship among the customer and the service companies that promotes a safe environment by monitoring crew work activities and equipment speeds, improving productivity, reducing operation expenses through improved job processes, better data management, and reduced operational failures.

Implementation of the invention on a conventional service rig can be conceptualized in two main aspects: 1) acquisition, recordation and transmission of transducer data such as hook load, hydraulic pressure, flow rate, etc. and 2) acquisition, recordation, and transmission of service-based activity, such as “Rig Up,” “Nipple Up Blow Out Preventer,” and “Pull Tubing,” among others. Acquisition of physical transducer or sensor data can be achieved through automated means, such as a transducer that converts pressure to an electrical signal being fed to an analog-to-digital converter and then to a recoding means, such as a hard drive in a computer or memory in a microprocessor. Acquisition of service-based activity may be achieved by service rig operator input into a microprocessor-based system. It is contemplated that the transducer data and activity data may be acquired by and stored by the same or different systems, depending the design and requirements of the service rig.

In a certain implementation of the invention, it may be desirable to make the acquisition and storage of the data at the well site secure to the extent that the service rig operator or other service company representatives are not able to manipulate or adulterate the data. One implementation of this inventive concept is to not allow error correction in the field. In other words, if the rig operator inadvertently inputs that a tubing pull service has begun when in fact the operation is nippling up the BOP, the operator can immediately input that the tubing pull has ended and input that the nipple up process has started. Additionally or alternatively, the operator may annotate an activity entry, or annotation may be restricted to personnel at the data center. It is also contemplated that the operator (or other inputer) can have complete editorial control over the data (both transducer data and activity data) received into the storage system.

The invention contemplates that transducer sensor data and/or activity data from third party service providers will also be input into the service rig data captive system. For example, third party service vehicles may utilize an identity beacon that emits a signal, such as an electromagnetic signal that is received by the instrumented service rig and records the time that the specific service rig arrived on site. Alternatively, the rig operator may manually input such information or other means such as magnetic cards or the like may be used. Once on site, transducer sensor data associated with the third party service operation, such as for example, flow rate or pressure, may be communicated to the instrumented rig via wire or wireless communication busses. The rig operator can input third-party activity data in a fashion similar to rig-based activities. In this and similar fashion, the instrumented service rig of the present invention can acquire, store and transmit all or substantially all of the physical and activity-based data that is generated by working over an oil well.

The following is a description of one exemplary embodiment of the present invention. It will be understood that this exemplary embodiment is but one way of implementing the present invention and does not necessarily implement all aspects of the invention. Therefore, the exemplary embodiment described below should not be construed to limit or define the outer boundaries of the present invention.

The amount of time a service rig spends at a well site can be broken down into discrete activities, each with a measurable beginning and ending time. One example of a typical series of service operations that might be performed at a well include moving onsite and rigging up the workover rig, pulling sucker rods, nippling up the blow out preventer (“BOP”), pulling tubing, other specified operations, running tubing, and well stimulation. Each activity has an identifiable start point which is associated with a certain time, and an identifiable end point that is associated with another certain time so that both the customer and the well service provider can ensure that the work was actually done and done in a timely manner.

Capturing the physical activities that take place at the well site can be determined by an evaluation of the sensor data from the transducers or by having the operator of the service rig input what happens at the well site. Operator input is used to capture and classify what activities are taking place at the well site, the time the activities are taking place, any exception events that prevent, restrict, or extend the completion of an activity, and the primary cause and responsible party associated with the exception events. Operator input is obtained by having the operator enter the activity data into a computer or microprocessor as the different service operations are taking place so that the customer and the service provider can have an accurate depiction of what goes on at the well site.

In one exemplary embodiment, the operator can simply type the activity information into a computer located at the well site. In another embodiment, a computer is provided to the operator with a number of pre-identified activities already programmed therein. When the operator starts or stops an activity, he can simply push a button or an area on a touch-screen display associated with the computer to log the stopping or starting of that pre-identified service activity. In a further embodiment, the operator is provided with a hierarchy of service tasks from which to choose from. Preferably, this service hierarchy is designed to be intuitive to the operator, in that the hierarchy is laid out in a manner that is similar to the progression of various service activities at a well site.

Service activities at a well site can generally be divided into three activity identifiers: global day-in/day-out (“DIDO”) well servicing activities, internal routine activities and external routine activities. DIDO activities are activities that occur almost every day that a service rig is at a well site. In the case of a mobile service rig, examples of DIDO activities include rigging up the service rig, pulling and laying down rods, pulling and laying down tubing, picking up and running tubing, picking up and running rods, and rigging down the service rig. Internal routine activities are those that frequently occur during well servicing activities, but aren't necessarily DIDO activities. Examples of internal routine activities include rigging up or rigging down an auxiliary service unit, longstroke, cut paraffin, nipple up/down a BOP, fishing, jarring, swabbing, flowback, drilling, clean out, well control activities such as killing the well or circulating fluid, unseating pumps, set/release tubing anchor, set/release packer, and pick up/laydown drill collars and/or other tools. Finally, external routine activities are routine activities that are commonly performed by third parties, such as rigging up/down third party servicing equipment, well stimulation, cementing, logging, perforating, or inspecting the well, and other common servicing tasks.

FIGS. 1A and 1B illustrate one example of a well servicing activity cycle. The job starts with the typical DIDO activities, shown in FIG. 1A, of rigging up the service unit, pulling and laying down rods, pulling and laying down tubing, and the respective transitions between those activities. After the tubing is pulled, other service activities are performed, most of which are selected from the list of internal routine activities and external routine activities described above and shown in FIG. 1B. After the selected internal and external routine activities are performed, the rig completes the job by picking up and running tubing and rods, and then rigging down the service unit.

In one embodiment, the operator enters the activity identifier (i.e. global day-in/day-out (DIDO) well servicing activities, internal routine activities and external routine activities) into the computer system. After the activity has been identified, the activity is classified based on the operator's subjective determination of how the activity is progressing to completion. The normal, default activity could be classified as “ON TASK: ROUTINE” wherein the job is proceeding according to plan. If for some reason the work is continuing, but not according to plan, two alternate activity classifications would be available to the operator to classify what is happening at the wellsite. Two such classifications could be “ON TASK: EXTEND,” in which the job is proceeding according to plan under conditions that may extend task times beyond what is normal, and “ON TASK: RE-SEQUENCE,” where the pre-planned job sequence has been interrupted, though work has not yet ceased. For example, changing from rigging up an auxiliary service unit to nippling up a BOP before the auxiliary service unit is completely rigged up would fall within this term. A single activity can be re-classified at any time while the activity is being performed. For instance, when a service rig starts rigging up, the “rig up” activity identifier would likely be classified as “ON TASK: ROUTINE.” However, if problems are encountered causing the rigging up time to extend beyond what the normal rigging up time, the “rig up” activity could then be reclassified as “ON TASK: EXTEND.”

In some instances, work is completely halted, and these cases, the operator would classify the activity as one of a number of exceptions. One type of exception classifications is “EXCEPTION: SUSPEND”, in which ongoing work activity has been interrupted due to a work-site condition and/or event that is temporary, and whose duration is unlikely to be longer than a set period of time, for instance, 10 minutes. Such “EXCEPTION: SUSPEND” conditions are generally non-emergency situations that include anything from a lunch or work break to a visit from the customer to discuss the well servicing operations. Another such exception classification is “EXCEPTION: WAIT” in which the pre-planned work process has been suspended due to the unavailability of a required resource, such as unavailable personnel, material, or an unavailable third-party service. A final type of exception classification is “EXCEPTION: DOWN,” in which the preplanned work process has ceased due to unplanned events and/or conditions occurring at the well site. Such unplanned events include change of scope of the service activity, changed well conditions, mechanical failure, weather, unsafe conditions, health and safety training events, and other unplanned events.

In one exemplary embodiment, for every activity classification other than “ON TASK: ROUTINE,” a variance identifier is assigned to the activity classification linking the reason for the non-routine classification to its source. If the activity classification is “ON TASK: EXTEND,” “ON TASK: RESEQUENCE,” or “EXCEPTION SUSPEND,” the variance identifier could be any of the aforementioned reasons for classifying exceptions, such as “SERVICE AVAILABILITY,” “MATERIAL AVAILABILITY,” “PERSONNEL AVAILABILITY,” “SCOPE CHANGE,” “WELL CONDITION CHANGE,” “MECHANICAL FAILURE,” “WEATHER, UNSAFE CONDITION,” “HEALTH AND SAFETY EVENT,” “WORK BREAK,” or other change in the work conditions. As described earlier, if the activity classification is “EXCEPTION: WAIT,” the variance identifier would be selected from as “SERVICE AVAILABILITY,” “MATERIAL AVAILABILITY,” or “PERSONNEL AVAILABILITY,” because “EXCEPTION: WAIT” is the activity classification in which the pre-planned work process has been suspended due to the unavailability of a required resource. If the activity classification is “EXCEPTION: DOWN,” the variance identifier would be selected from the group comprising “SCOPE CHANGE,” “WELL CONDITION CHANGE,” “MECHANICAL FAILURE,” “WEATHER, UNSAFE CONDITION,” “HEALTH AND SAFETY EVENT,” “WORK BREAK,” or other unanticipated change in the work conditions. This is because the “EXCEPTION: DOWN” activity classification covers exceptions in which the preplanned work process has ceased due to unplanned events and/or conditions occurring at the well site.

After the variance identifier has been selected, the variance can be classified appropriately so as to be assigned to a responsible party. Generally, the responsible party will be the well service provider, a third party, or the customer. In one embodiment, the variance classification will be selected between “WELL SERVICE PROVIDER,” “CUSTOMER” or “3RD PARTY.” After the variance classification has been selected, the operator is done entering information in to the computer until the present activity is completed or the next activity is started.

Referring to FIG. 2, one embodiment of the aforementioned activity capture and display system is outlined in tabular form. As is shown in FIG. 2, an operator first chooses an activity identifier for his/her upcoming task. If “GLOBAL” is chosen, then, as shown in FIG. 1A, the operator would choose from rig up/down, pull/run tubing or rods, or laydown/pickup tubing and rods (options not shown in FIG. 2). If “ROUTINE: INTERNAL” is selected, then the operator would choose from rigging up or rigging down an auxiliary service unit, longstroke, cut paraffin, nipple up/down a BOP, fishing, jarring, swabbing, flowback, drilling, clean out, well control activities such as killing the well or circulating fluid, unseating pumps, set/release tubing anchor, set/release packer, and pick up/laydown drill collars and/or other tools, as shown in FIG. 1B. Finally, if “ROUTINE: EXTERNAL” is chosen, the operator would then select an activity that is being performed by a third party, such as rigging up/down third party servicing equipment, well stimulation, cementing, logging, perforating, inspecting the well, and/or other common third party servicing tasks, as shown in FIG. 1B. After the activity is identified, it is classified. For all classifications other than “ON TASK: ROUTINE,” a variance identifier is selected, and then classified using the variance classification values.

As explained above, all that is required from the operator is that he or she enter in the activity data into a computer, such as the one shown in FIG. 3. The operator can interface with the computer using a variety of means, including typing on a keyboard, using a mouse or other input device, or using a monitor that is designed as a touch-screen display. In one embodiment, a monitor 48 with pre-programmed buttons 10 is provided to the operator, such as the one shown in FIG. 3, which allows the operator to simply select the activity from a group of pre-programmed buttons. For instance, if the operator were presented with the screen of FIG. 3 upon arriving at the well site, the operator would first press the “RIG UP” button. The operator would then be presented with the option to select, for example, “SERVICE UNIT,” “AUXILIARY SERVICE UNIT,” or “THIRD PARTY.” The operator then would select whether the activity was on task, or if there was an exception, as described above.

An example of an activity capture map for pulling operations is shown in FIG. 4. If an operator were to select “PULL” from the top screen, he would then have the option to select between “RODS,” “TUBING,” “DRILL COLLARS,” or “OTHER.” If the operator chose “RODS,” the operator would then choose from “PUMP,” “PART,” “FISHING TOOL,” or “OTHER.” The operator would be trained on the start and stop times for each activity, as shown in the last to columns of FIG. 4 so that the operator could appropriately document the duration of the activity at the well site. Each selection would have its own subset of tasks, as described above, but for ease of understanding, only those pulling rods or shown in FIG. 4.

In one embodiment of the present invention, the activity data is gathered by the computer along with process data from the well service vehicle, such as is described in U.S. Pat. No. 6,079,490, which is hereby incorporated by reference. Referring to FIG. 5, a retractable, self-contained mobile service rig 20 is shown to include a truck frame 22 supported on wheels 24, an engine 26, a hydraulic pump 28, an air compressor 30, a first transmission 32, a second transmission 34, a variable speed hoist 36, a block 38, an extendible derrick 40, a first hydraulic cylinder 42, a second hydraulic cylinder 44, a first transducer 46, a monitor 48, and retractable feet 50. Monitor 48, of special importance to the disclosed invention, receives amongst other things various parameters measured during the mobile service rig's operation.

Engine 26 selectively couples to wheels 24 and hoist 36 by way of transmissions 34 and 32, respectively. Engine 26 also drives hydraulic pump 28 via line 29 and air compressor 30 via line 31. Compressor 30 powers a pneumatic slip 84, and the hydraulic pump 28 powers a set of hydraulic tongs. The hydraulic pump 28 also powers cylinders 42 and 44 that respectively extend and pivot derrick 40 to selectively place derrick 40 in a working position and in a retracted position. In the working position, the derrick 40 is pointed upward, but its longitudinal centerline 54 is angularly offset from vertical as indicated by angle 56 of FIG. 5. This angular offset 56 provides block 38 access to a well bore 58 without interference from the derrick framework and allows for rapid installation and removal of inner pipe segments (i.e., inner pipe strings 62) and sucker rods as shown in FIG. 6.

Individual pipe segments (of string) and sucker rods are screwed together using hydraulic tongs. Hydraulic tongs are known in the art, and refer to any hydraulic tool that can screw together two pipes or sucker rods, such as those provided by B. J. Hughes company of Houston, Tex. In operation, the hydraulic pump drives a hydraulic motor in either forward or reverse directions by way of valve. The hydraulic motor drives pinions that turn a wrench element relative to clamp. The wrench element and the clamp engage flats on mating couplings of a sucker rod or inner pipe string; however, rotational jaws or grippers that hydraulically clamp on to a round pipe (i.e., with no flats) can also be used in place of the disclosed wrench element. The rotational direction of hydraulic motor determines whether the couplings are assembled or disassembled.

A transducer detects by feedback the amount of torque that is used to assemble or disassemble the string or sucker rods, and provides an analog or digital signal (e.g., from 0-5 Volts DC) indicative of that torque value. This signal is provided to a monitor 48 and is stored in a manner to be described shortly.

When installing inner pipe string segments, a pneumatic slip is used to hold the pipe string while the next segment is screwed on using tongs as just described. A compressor provides pressurized air through a valve to rapidly clamp and release the slip. A tank helps maintain constant air pressure. A pressure switch, a type of transducer or sensor, provides the monitor 48 with a signal that indirectly indicates that repair unit 20 is in operation.

Referring back to FIG. 5, weight applied to block 38 is sensed by way of a hydraulic pad 92 that supports the weight of derrick 40. Hydraulic pad 92 is basically a piston within a cylinder such as those provided by M. D. Totco company of Cedar Park, Tex., but can alternatively constitute a line indicator or a diaphragm. Hydraulic pressure in pad 92 increases with increasing weight on the block 38, and this pressure can accordingly be monitored to assess the weight of the block 38. Thus, the hydraulic pad 92 constitutes another type of transducer, and it too transmits a signal (not shown) to the monitor 48.

In short, and as is well known, the mobile service rig contains numerous tools for performing various repair tasks, and most of these tools contain some sort of transducer for providing an indication of the work being performed. (As used herein, “transducer” should be understood as any sort of detector, sensor, or measuring device for providing a signal indicative of the work being performed by a particular tool). Using such transducers, important parameters can be measured or monitored, such as hook load, tong torque, engine RPM, hydrogen sulfide concentration, a block position encoder for determining where the block is in is travel, engine oil pressure, clutch air pressure, global positioning system monitor, and any other sensor that might provide data worth being monitored by the well service provider.

As noted above, the signals provide by the various transducers/sensors associated with the tools are sent to the data acquisition monitor 48. The primary objective of the monitor 48 is to gather well maintenance data and save it so that it can be transferred and subsequently monitored at a site other than the location of the mobile service rig, such as a central office site, where a supervisor or owner can view the data on another monitor 48 or other display device known to those or ordinary skill in the art. The monitor 48 is generally installed in an openly accessible location on the mobile service rig 20. For example, on a mobile service rig 20, the monitor 48 is installed somewhere outside the cab for easy access by human operators who may walk up to the mobile service rig 20 to interface with the system and collect data. In an alternative exemplary embodiment, the data can be transmitted via wireless communication to a computer or other display device to an evaluator in the same or different location. In addition to storing the measured data from the tools, the monitor 48 may also include a screen display for displaying the data.

The signals provide by the various sensors associated with the tools can be sent to the same or a different computer at which the operator enters the activity data at the will. The computer(s) can then gather well maintenance data and save it so that it can be correlated to the activity data entered by the operator. In one embodiment, the process data can be displayed on a screen for the operators to review. In yet another exemplary embodiment, the activity data and the process data can be transferred and subsequently monitored at a site other than the location of the mobile service rig 20, such as a centrally located office site. In one embodiment, the activity and process data is transferred using a modem and cellular phone arrangement such as is described in U.S. Pat. No. 6,079,490. In other embodiments, the data is transferred using other types of wireless communication, such as via a satellite hookup (Not Shown). The data can also be transferred using a hard disk medium, wherein the data is saved on a floppy disk, CD, or other memory storage device and physically transferred to the central office site. There are a wide variety means to transfer the data from the well site to the central office site, and such means are widely known in the art and are considered within the scope of this invention.

Processes of exemplary embodiments of the present invention will now be discussed with reference to FIGS. 9, 11, and 13. Certain steps in the processes described below must naturally precede others for the present invention to function as described. However, the present invention is not limited to the order of the steps described if such order or sequence does not alter the functionality of the present invention in an undesirable manner. That is, it is recognized that some steps may be performed before or after other steps or in parallel with other steps without departing from the scope and spirit of the present invention.

Turning now to FIGS. 7, 7A and 8 an illustration of exemplary displays 700, 750, 800 that include activity Gantt charts in accordance with an exemplary embodiment of the present invention are shown and described within the exemplary operating environment of FIGS. 5 and 6. Now referring to FIGS. 5, 6, 7, 7A, and 8, the exemplary display 700 includes an activity Gantt chart 705. The exemplary display 700 also includes, in one exemplary embodiment, charts for other sensors on the repair unit 20, including, but not limited to an engine speed chart 710, a hydraulic pressure chart 715, and a rig load chart 720. The activity Gantt chart 705, engine speed chart 710, hydraulic pressure chart 715, and rig load chart 720 each include an X-axis represented by time. In one exemplary embodiment, the activity Gantt chart 705 represents time in hours and minutes, however other methods of tracking data against time can be used. The engine speed chart 710 includes a Y-axis representing engine speed in revolutions per minute (“rpm”). The hydraulic pressure chart 715 includes a Y-axis representing hydraulic pressure in pounds per square inch (“psi”). The rig load chart 720 includes a Y-axis representing weight in pounds.

In one exemplary embodiment, the operator of the repair unit 20 or an off-site or on-site supervisor may view the display 700 on the monitor 48 of FIG. 5 or a monitor 48 positioned at another location that can be on-site or off-site. The repair unit operator inserts the activities by pressing icons or buttons 10, as shown in FIG. 3, to tell the system what activity he is performing at any given time. When they want to view the activity Gantt chart, the operator or supervisor can select an icon or button requesting its display on the monitor 48. In one exemplary embodiment, the view is as shown on the display 700 of FIG. 7, such that the spacing provided for in a normal view of the four charts 705-720 does not allow the activity Gantt chart 705 to display the descriptions of each activity 725, 730.

The operator can key in or press a button 10 sending an input to the system to zoom-in on a smaller period of time as shown in display 750 of FIG. 7A. The activity Gantt chart 705 of FIG. 7A includes a first activity time period 735. As can be seen in the Gantt chart 705, the activity for the first activity time period 735 is described as “Nipple up/down BOP”. The Gantt chart 705 also includes a second activity time period 740. In one exemplary embodiment, the Gantt chart 705 displays each subsequent activity along the timeline at a position along the Y-axis above the level of the next preceding activity. The second activity time period 740 includes a description of the activity as “reconfigure hoisting/handling equipment,” which can represent a normal in-sequence event that a rig crew completes between tasks, such as changing out rod tongs for tubing tongs, reversing tong heads, etc. In one exemplary embodiment, the Gantt chart 705 is capable of graphically representing every activity completed by the repair unit 20, activities of third parties, as well as reasons for the repair unit 20 not completing activities as discussed in FIGS. 1-6.

FIG. 9 is a logical flowchart diagram illustrating an exemplary method 900 for evaluating and determining the accuracy of an activity Gantt chart 705 based on a review of sensor data on a display as shown in FIGS. 7, 7A and 8. Now referring to FIGS. 7, 7A, 8, and 9, the exemplary method 900 begins at the START step and continues to step 905 where a request is received to display the activity Gantt chart 705 on the display 700. In step 910, the activity Gantt chart 705 is displayed along with the engine speed chart 710, hydraulic pressure chart 715, and rig load chart 720. In one exemplary embodiment, the charts 705-720 are displayed one on top of another so that the time periods represented by each chart are vertically aligned with one another. In one exemplary embodiment, the charts 705-720 are displayed on the monitor 48 of FIG. 3 or 5.

In step 915, the rig operator or supervisor, well owner, service rig owner, or other evaluator (collectively the “supervisor”) determines the first activity from the activity Gantt chart 705. As shown in FIG. 7A, the first activity is represented by the first activity time period 735. In an alternative embodiment, the first activity can be determined by reviewing a written report. The written report can be created by a supervisor or rig crew member, in one exemplary embodiment the service rig operator, and can be generated daily, per shift, per job, or any other time interval, for example every hour or twelve-hour period. In one exemplary embodiment, the written report is generated each shift by the rig operator. In one exemplary embodiment, the written report includes the name or identification of the customer and the well or wells being serviced, the activities that took place during that shift, or reasons for downtime, and the time that it took to complete each activity or the amount of downtime based on each individual cause of the downtime. While the written report does not look exactly like the Gantt chart 705, those of ordinary skill in the art, including supervisors and customers are capable of reading a written report generated by a rig crew conducting service activities and determining information related to what activities were conducted at the well during the service period and the time period for each service activity or downtime activity.

The start and completion times for the first activity are determined in step 920. For example, the start time for the first activity time period 735 is approximately 9:16 and the end time is approximately 9:58. Counter variable X is set equal to one in step 925. In one exemplary embodiment, counter variable X represents a chart of sensor data from the rig 20, such as charts 710-720. In step 930, the supervisor evaluates the data generated in the first chart during the time period 735 for the first activity. In one exemplary embodiment, as shown in FIG. 7A, the supervisor determines the activity listed for the first activity time period 735 and looks at the same time period for the engine speed chart 710 to determine if the data presented by the engine speed chart 710 for that time period 735 is consistent with the activity, nipple up/down BOP, listed for that time period 735.

In step 935, an inquiry is conducted to determine if the data in the first chart is consistent with the first activity in the Gantt chart 705. If not, the “NO” branch is followed to step 965, where the supervisor solicits additional information from the rig operator to determine why the Gantt chart 705 did not list the correct activity. The process then continues from step 965 to step 955. On the other hand, if the data in the first chart is consistent with the first activity, the “YES” branch is followed to step 940.

In step 940, an inquiry is conducted to determine if there is another chart to evaluate on the display 750. In one exemplary embodiment, the charts that can be displayed and evaluated by a supervisor can include one or more charts, of which all or only a portion of the charts being evaluated may be viewable on the monitor 48 or display at a single time. In the exemplary display 750 of FIG. 7A, three charts 710-720 are viewable and capable of being compared to the activity Gantt chart 705. As discussed above with reference to the engine speed chart 705, the supervisor compares the time period of the first activity time period 735 to the same time periods in the hydraulic pressure chart 715 and the rig load chart 720 to determine if the data from each chart 715, 720 is consistent with data that would be output by sensors providing that data during the activity listed for the first activity time period 735. If there is another chart to evaluate, the “YES” branch is followed to step 945, where the counter variable X is incremented by one. The process then returns from step 945 to step 930 to evaluate the data in the next chart for the first time period 735.

Returning to step 940, if there are no additional charts to evaluate, the “NO” branch is followed to step 950, where the time to complete the activity is evaluated to determine if an excessive amount of time passed to complete the listed activity. In step 955, an inquiry is conducted to determine if there is another activity listed on the activity Gantt chart 705. In the example of FIG. 7A, a second activity is represented by the second activity time period 740 and the activity was designated as “reconfigure hoisting/handling equipment. If there is another activity, the “YES” branch is followed to step 960, where the supervisor selects the next activity for evaluation. The process then returns from step 960 to step 920 to determine the start and completion times for the next activity. If the Gantt chart 705 does not include additional activities for evaluation, the “NO” branch is followed to the END step.

FIG. 8 provides an exemplary display 800 illustrating a Gantt chart 705 listing activities that do not correspond with the data provided by sensors on the rig 20 to the charts 710-720. Referring now to FIG. 8, a third activity time period 805 represents an activity on the Gantt chart 705 listed as “pump/circulate kill fluid”. However, the time period 810 shows high engine speeds on the engine speed chart 710, fluctuating levels of high and low hydraulic pressure on the hydraulic pressure chart 715, and a load of fifty thousand pounds on the rig load chart 720. The data provided by charts 710-720 for time period 810 is inconsistent with pumping and circulating kill fluid as listed in the fourth activity time period 805. Instead, an analysis of the data provided by charts 710-720 for time period 810 is more consistent with pulling and running rods. Based on this analysis, as discussed in FIG. 9, the supervisor would solicit information from the rig operator to determine why the Gantt chart 705 does not list the correct activity.

FIGS. 10 and 11 represent an exemplary display 1000 and method 1100 for measuring transition times by evaluating the display of readings from sensors on the rig 20 according to one exemplary embodiment of the present invention. Now referring to FIGS. 5, 6, and 10, transition times, the time is takes to accomplish a task, can be identified by examining the data curves presented in the engine speed chart 710, the hydraulic pressure chart 715, and the rig load chart 720 or other exemplary charts of sensor data known to those of ordinary skill in the art from the rig 20. For example, a first time interval 1005 represents the time the rig 20 is being driven to a service site. This activity is determined by evaluating the data provided in the charts 710-720. The engine speed on the engine speed chart 710 for the first time interval 1005 shows high engine rpm's while the hydraulic pressure on the hydraulic pressure chart 715 and the rig load on the rig load chart 720 for the first time interval 1005 are zero or substantially zero. This combination of data alerts the supervisor that the activity being completed at this time is rig 20 being driven to or from a well site.

The activity occurring during the second time interval 1010 shown in the rig load chart 720 is the mast 40 being removed from the head ache rack (Not Shown) on the rig 20 and standing up on the hydraulic pad indicator 92 of FIG. 5. The activity is determined by evaluating the charts 710-720, which show that the weight on the hydraulic pad indicator 92 increases from zero to approximately twenty thousand pounds at data point 1035, which is generally the weight of the raised derrick 40 with the leveling jacks (not shown) still in place, while the engine is operating at approximately thirteen hundred revolutions per minute at data point 1015, which is generally the speed of the engine when it is raising the derrick 40. The mast 40 is then extended, or scoped out, and the leveling jacks are retracted. This part of activity 1010 can be determined by evaluating the charts 710-720, which show that at data point 1020 the engine of the rig 20 is operating at a speed of approximately twenty-three hundred revolutions per minute, which is generally the speed necessary to extend the derrick 40, and the rig weight on the hydraulic pad indicators 92 had increased from twenty thousand to approximately forty thousand pounds, which is generally the weight of the extended derrick 40 on the pad indicators 92 after the leveling jacks (not shown) have been retracted. An operator of ordinary skill would also know this to be the activity because the hydraulic pressure in chart 715 stays substantially at the zero level during the activity 1010.

The activity occurring during the third time interval 1025, shown in the rig load chart 720, is the crew of the rig working a pump loose from a stuck position. The activity is determined by evaluating the charts 710-720, which show that the maximum weight limits viewable on the rig load chart 720 and high engine speeds on the engine speed chart 710 were observed during the third time interval 1025; however, there is virtually no hydraulic pressure displayed during the third time interval 1025.

The activity occurring during the fourth time interval 1030, shown in the rig load chart 720, is the rig 20 pulling rods out of the well 58. The activity is determined by evaluating the data on the charts 710-720, which show the cyclical increases in the engine speed, hydraulic pressure and rig load weight occurring at the same time intervals during the fourth time interval 1030 and indicative of rods being pulled from the well 58.

Now turning to FIG. 11, an exemplary process for measuring the completion times for jobs completed by evaluating the exemplary electronic display 1000 begins at the START step and continues to step 1105 where the system receives an input selecting the display of charts 710-720. In one exemplary embodiment, the charts can be reviewed on the monitor 48 of FIG. 5. In an alternative embodiment, the charts 710-720 may be viewed by printing them out on a printer or plotter, or other hard-copy format known to those of ordinary skill in the art.

In step 1110, a supervisor evaluates the charts 710-720 on the display 1000. Counter variable X is set equal to one in step 1115. In one exemplary embodiment, counter variable X represents an activity conducted by the service rig 20. The supervisor determines the first activity based on an evaluation of the data curves for the charts 710-720 in the display 1000 in step 1120. In step 1125, the supervisor determines the second activity based on an evaluation of the data curves in the charts 710-720 in the display 1000. In step 1130, the supervisor evaluates the data curves in the charts 710-720 to determine the beginning of the first activity and the beginning of the second activity. Returning to the example in FIG. 10, based on the data that is viewable, the beginning of the first activity, represented by the first time interval 1005, is approximately 7:40 while the time at the beginning of the second activity, represented by the second time interval 1010, is approximately 8:22.

In step 1135, the difference between the beginning time of the first activity and the beginning time of the second activity is recorded as the time to complete the first activity. In one exemplary embodiment the completion time can be recorded in a conventional database in a computer, however, those of ordinary skill in the art will recognize that many other methods or recording the data may be used, including, but not limited to, entering the completion time data onto a data sheet for placement into a record file. In an alternative embodiment, the completion time for a task may be determined by determining the beginning time of a task and the end time of the same task and recording the difference between those two times as the time to complete the task. Retuning to the example in FIG. 10, the beginning time for the first task is approximately 7:40 and the completion time for the first task is approximately 7:55, which would be a completion time of approximately fifteen minutes.

The supervisor determines if the completion time for the activity is excessive in step 1140. In one exemplary embodiment, the supervisor can use his personal judgment to make this determination or he may reference additional data that provides the average time to complete this task and/or acceptable time ranges for completing this task and use that information for the determination. In step 1145, an inquiry is conducted to determine if the activity completion time is excessive. If so, the “YES” branch is followed to step 1150, where additional instruction is provided to the crew related to that activity or disciplinary action is taken against the crew members for that rig 20. If the completion time for that activity is not excessive, the “NO” branch is followed to step 1155.

In step 1155, an inquiry is conducted to determine if there is another activity shown on the charts 710-720 in the display 1000. If so, the “YES” branch is followed to step 1160, where counter variable X is incremented by one. The process then returns from step 1160 to step 1120 to evaluate the completion time for the next activity. On the other hand, if there are no additional activities based on an evaluation of the display 1000, the “NO” branch is followed to the END step.

FIGS. 12 and 13 represent an exemplary display 1200 and method 1300 for measuring wait times or downtimes by evaluating the display 1200 of readings from sensors on the rig 20 according to one exemplary embodiment of the present invention. Now referring to FIGS. 3, 5, and 12, downtimes can be identified by curves on the charts 710-720 that are inactive or flat. During downtimes, the engine 26 for the rig 20 may or may not be running and the rig 20 may or may not be registering a load on the rig load chart 720. In one exemplary embodiment, prior to calling a period a downtime the data on the charts 710-720 must be examined in sequence with the other activities shown in the display 1200 to determine what is happening on the rig 20. For example, nippling up a blow out preventer often looks like downtime, but that is normally in a sequence of events prior to pulling tubing from the well.

In FIG. 12, an evaluation of the charts 710-720 for a first time period 1205 shows that the rig 20 is pulling rods out of the well and hanging them in the derrick. During the second time period 1210, the load data in the rig load chart 720 is virtually constant (flat) and shows a load of approximately forty-six thousand pounds. For that same time period 1220 on the hydraulic pressure chart 720, the hydraulic pressure data is substantially zero for the entire time period 1220. During that same time period 1125 on the engine speed chart 710, the engine speed is zero for a substantial portion of that time period. The time period shown by 1210, 1220, 1225 is considered a downtime based on the data provided by the charts 710-720. This is confirmed by evaluating the third time period 1215, where the supervisor can determined from the data on the charts that the rig 20 is running rods and a pump back into the well 58 during that time period 1220. In one exemplary embodiment, a pump change can be determined by evaluating the time periods and recognizing that the third time period 1215 is immediately after or substantially close in time after the third time period, typically about ten minutes. Generally, any time over the ten minute time period would be classified as flat or downtime, in one exemplary embodiment.

Now turning to FIG. 13, an exemplary process for determining downtime by evaluating the charts 710-720 on the exemplary electronic display 1200 begins at the START step and continues to step 1305 where the supervisor reviews the charts 710-720 on the display 1200. Counter variable X is set equal to one in step 1310. In one exemplary embodiment, counter variable X represents a chart of data from a sensor at the rig 20. In step 1315 the first chart is evaluated to determine if there is a predetermined amount of time that the curve for the first chart is off or substantially flat. In one exemplary embodiment any of the charts 710-720 in FIG. 12 or any other charts of sensor data from the rig 20 may be considered as the first chart for evaluation purposes. In one exemplary embodiment, the predetermined amount of time is fifteen minutes; however, longer and shorter time period are within the scope of this invention.

In step 1320, an inquiry is conducted to determine if a portion of the first chart contains data that is substantially flat or that is missing for a predetermined amount of time. If the first chart does not contain an area of data that is substantially flat or missing, the “NO” branch is followed back to step 1315 where evaluation of the first chart continues. On the other hand, if there is a portion of the chart that has data that is substantially flat or missing, the “YES” branch is followed to step 1325, where the time period of the flat data is determined. For example, in FIG. 12, an evaluation of the data in the rig load chart 720 shows a time period 1210 of data that is substantially flat for more than fifteen minutes. A review of that time period 1210 shows the start of the time period 1210 is approximately 11:20 a.m. and the end is approximately 2:15 p.m.

In step 1330, an inquiry is conducted to determine if the is another chart of sensor data from the rig 20. Returning to the example of FIG. 12, the charts 710 and 715 would satisfy this inquiry. If there are no additional charts on the display 1200, the “NO” branch is followed to step 1345, where the time period is classified as a downtime period. If there are additional charts to evaluate, the “YES” branch is followed to step 1335, where counter variable X is incremented by one. In step 1340, an inquiry is conducted to determine if the next chart, for example the hydraulic pressure chart 715, has a substantially flat curve or missing data for the same time period 1210. If the second chart does not have a substantially flat curve or missing data for that time period 1210, the “NO” branch is followed to step 1310. Otherwise the “YES” branch is followed to step 1330. As can be seen in the exemplary display 1200 of FIG. 12, during the time period 1210, the hydraulic pressure chart 715 has a time period 1220 that contains data that is substantially flat, and the engine speed chart 710 contains a time period 1225 that contains data that is substantially flat.

In step 1350, an inquiry is conducted to determine if the downtime period is excessive. If so, the “YES” branch is followed to step 1355, where the supervisor can solicit additional information from the rig operator to determine the reason for the rig 20 downtime or the rig crew can be disciplined for the excessive downtime. The process then continues from step 1355 to the END step. On the other hand, if the downtime period is not excessive, the “NO” branch is followed to the END step.

Although the invention is described with reference to a preferred embodiment, it should be appreciated by those skilled in the art that various modifications are well within the scope of the invention. Therefore, the scope of the invention is to be determined by reference to the claims that follow. From the foregoing, it will be appreciated that an embodiment of the present invention overcomes the limitations of the prior art. Those skilled in the art will appreciate that the present invention is not limited to any specifically discussed application and that the embodiments described herein are illustrative and not restrictive. From the description of the exemplary embodiments, equivalents of the elements shown therein will suggest themselves to those or ordinary skill in the art, and ways of constructing other embodiments of the present invention will suggest themselves to practitioners of the art. Therefore, the scope of the present invention is to be limited only by any claims that follow. 

1. A method of determining the accuracy of an activity listing for activities completed at a well site comprising the steps of: a. receiving a first activity from an activity listing; b. evaluating at least one chart of sensor data associated with work completed at the well site; and c. determining if the sensor data is consistent with the first activity.
 2. The method of claim 1, further comprising the steps of: determining a start time for the first activity by evaluating the activity listing; determining a finish time for the first activity by evaluating the activity listing; and evaluating the sensor data on the chart between the start time and the finish time of the first activity.
 3. The method of claim 2, further comprising the step of soliciting information from a rig operator if the sensor data is not consistent with the first activity.
 4. The method of claim 1, further comprising the steps of: d. repeating steps (b)-(c) for each chart of sensor data associated with work completed at the well site; and e. repeating steps (a)-(d) for each additional activity in the activity listing.
 5. The method of claim 1, wherein the activity listing comprises an activity Gantt chart.
 6. The method of claim 1, wherein the activity Gantt chart and each of the charts of sensor data are presented on a monitor.
 7. The method of claim 6, further comprising the step of receiving a request to display the activity Gantt chart on the monitor.
 8. The method of claim 1, wherein the activity is selected from a group consisting of rigging up a service rig, pulling rods, laying down rods, pulling tubing, laying down tubing, picking up tubing, running tubing, picking up rods, running rods, rigging down the workover rig, rigging up an auxiliary service unit, rigging down an auxiliary service unit, longstroke, cut paraffin, nipple up a blow out preventer, nipple down a blow out preventer, fishing, jarring, swabbing, flowback, drilling, clean out, well control activities, killing a well, circulating fluid within a well, unseating pumps, setting a release tubing anchor, releasing a tubing anchor, setting a packer, releasing a packer, picking up drill collars, laying down drill collars, picking up tools, laying down tools, rigging up third party servicing equipment, well stimulation, cementing, logging, perforating, inspecting the well, and traveling to the well site.
 9. The method of claim 1, wherein the sensor data is obtained from at least one sensor on the well service rig.
 10. The method of claim 1, wherein the at least one chart comprises a rig load chart.
 11. The method of claim 1, wherein the at least one chart comprises a hydraulic pressure chart.
 12. The method of claim 1, wherein the at least one chart comprises an engine speed chart.
 13. A method of determining completion times for an activity completed by a well service rig at a well site comprising the steps of; evaluating a plurality of charts of sensor data associated with work completed at the well site; determining a first activity based on an evaluation of the data in the plurality of charts; evaluating at least one of the plurality of charts to determine a time to complete the first activity; and recording the time to complete the first activity in a computer program.
 14. The method of claim 13, further comprising the steps of: determining if the time to complete the first activity is too long; and providing additional training for the first activity to a crew of the well service rig.
 15. The method of claim 13, wherein determining the time to complete first activity comprises the steps of: evaluating at least one of the charts of sensor data to determine when the first activity was initiated; evaluating at least one of the charts of sensor data to determine when a second activity was initiated, wherein the second activity occurs subsequent to the first activity; and determining a time difference between the beginning of the first activity and the beginning of the second activity, wherein the time difference comprises the time to complete the first activity.
 16. The method of claim 13, wherein determining the time to complete the first activity comprises the steps of: evaluating at least one of the chart of sensor data to determine when the first activity was initiated; evaluating at least one of the charts of sensor data to determine when the first activity was completed; and determining a time difference between the beginning of the first activity and the completion of the first activity, wherein the time difference comprises the time to complete the first activity.
 17. The method of claim 13, wherein the plurality of charts of sensor data are presented on a monitor.
 18. The method of claim 17, further comprising the step of receiving a request to display the at least one of the plurality of charts on the monitor.
 19. The method of claim 13, wherein the first activity is selected from a group consisting of rigging up a service rig, pulling rods, laying down rods, pulling tubing, laying down tubing, picking up tubing, running tubing, picking up rods, running rods, rigging down the workover rig, rigging up an auxiliary service unit, rigging down an auxiliary service unit, longstroke, cut paraffin, nipple up a blow out preventer, nipple down a blow out preventer, fishing, jarring, swabbing, flowback, drilling, clean out, well control activities, killing a well, circulating fluid within a well, unseating pumps, setting a release tubing anchor, releasing a tubing anchor, setting a packer, releasing a packer, picking up drill collars, laying down drill collars, picking up tools, laying down tools, rigging up third party servicing equipment, well stimulation, cementing, logging, perforating, inspecting the well, and traveling to the well site.
 20. The method of claim 13, wherein the sensor data is obtained from at least one sensor on the well service rig.
 21. The method of claim 13, wherein the plurality of charts comprises a rig load chart.
 22. The method of claim 13, wherein the plurality of charts comprises a hydraulic pressure chart.
 23. The method of claim 13, wherein the plurality of charts comprises an engine speed chart.
 24. The method of claim 13, further comprising the step of consolidated the plurality of charts of sensor data associated with work completed at the well site into one chart for evaluation on a monitor.
 25. A method of determining downtime of a well service rig at a well site by evaluating a plurality of charts of sensor data comprising the steps of; a. evaluating a first chart from the plurality of charts of sensor data associated with work completed at the well site; b. determining if at least a portion of the data curve on the first chart is substantially flat for a predetermined amount of time; c. determining a time period where the data curve on the first chart is substantially flat based on a positive determination that the first chart comprises a portion of the data curve that is substantially flat for a predetermined amount of time; d. evaluating at least one additional chart from the plurality of charts of sensor data associated with work completed at the well site to determine if each additional chart comprises a data curve that is substantially flat for the time period; and e. designating the time period as a downtime period.
 26. The method of claim 25, further comprising the steps of: f. determining if the downtime period is an excessive downtime period; g. soliciting additional information from an operator of the well service rig to determine the reason for the excessive downtime period; and h. repeating step (b)-(e) to determine additional downtime periods.
 27. The method of claim 25, wherein the predetermined amount of time is fifteen minutes.
 28. The method of claim 25, wherein the sensor data is obtained from at least one sensor on the well service rig.
 29. The method of claim 25, wherein the plurality of charts comprises a rig load chart.
 30. The method of claim 25, wherein the plurality of charts comprises a hydraulic pressure chart.
 31. The method of claim 25, wherein the plurality of charts comprises an engine speed chart.
 32. The method of claim 25, wherein the plurality of charts of sensor data are presented on a monitor.
 33. The method of claim 25, further comprising the step of receiving a request to display the at least one of the plurality of charts on the monitor.
 34. A method of determining the accuracy of a written report comprising a listing of service rig activities conducted at a well site comprising the steps of: a. determining a first activity from the written report of service rig activities; b. evaluating at least one chart of sensor data associated with work completed at the well site; and c. determining if the sensor data is consistent with the first activity from the written report.
 35. The method of claim 34, further comprising the steps of: determining a start time for the first activity by evaluating the written report of service rig activities; determining a finish time for the first activity by evaluating the written report of service rig activities; and evaluating the sensor data on the chart between the start time and the finish time of the first activity.
 36. The method of claim 34, wherein determining if the sensor data is consistent with the first activity from the written report is completed by a customer receiving the service rig activities.
 37. The method of claim 34, further comprising the steps of: d. repeating steps (b)-(c) for each chart of sensor data associated with work completed at the well site; and e. repeating steps (a)-(d) for each additional activity from the written report of service rig activities.
 38. The method of claim 34, wherein the written report of service rig activities is generated for each work shift completed by a rig crew operating the service rig.
 39. The method of claim 34, wherein each of the charts of sensor data are presented on a monitor.
 40. The method of claim 34, wherein the sensor data is obtained from at least one sensor on the well service rig.
 41. The method of claim 34, wherein the at least one chart comprises a rig load chart.
 42. The method of claim 34, wherein the at least one chart comprises a hydraulic pressure chart.
 43. The method of claim 34, wherein the at least one chart comprises an engine speed chart. 